The present invention relates to elastic fluid turbines and more particularly to systems and methods for operating steam turbines and to electric power plants in which generators are operated by steam turbines.
One general type of steam is the extraction type which typically although not necessarily would be classed as a small turbine and which further would be typically designed to supply the extracted steam required for a plant process and the turbine motive flow required for driving an industrial plant or electric power plant generator of predetermined electric power rating. Thus, an extraction turbine of suitable design rating might act as a prime mover in operating a paper mill plant generator while simultaneously supplying steam flow extracted from the main turbine steam flow for the paper making process and other purposes. Operation as a prime mover may be either a primary or a secondary role of the extraction turbine. Other turbines similar in end function to the extraction type include (1) back pressure turbines which exhaust motive steam flow under pressure control for process, heating or other purposes and (2) seawater conversion turbines which operate electric power generators and supply the steam flow needed for heating the converted seawater in a desalination plant. Turbines employed in the latter application may be of the extraction or back pressure type.
Another general type of steam turbine is that in which the steam is used primarily only to operate the turbine as a prime mover in power plant and other applications. In large electric power generation plants, such turbines drive large electric generators and are therefore of relatively large size and capacity. Turbine configurations vary from power plant application to application, and, in a fossil fuel fired plant, a turbine typically might include high pressure, intermediate pressure and low pressure sections tandemly interconnected on a single or multiple shaft with one or more successive reheat stages between the sections. A preselected power plant steam generating system provides steam to operate the turbine primarily only to generate electric power, but the turbine may also perform some relatively low power auxiliary functions such as boiler feed pump operation. Other prime mover turbines include shipboard electric generation turbines and ship propulsion turbines which are operated to control propeller torque and ship speed.
The extraction and prime mover turbines are the principal turbine types which are defined by the partitioning of different kinds of steam turbines on the basis of the character of the use made of the turbine inlet steam. Partitioning can also be made on the basis of the character of the steam generating system, and fossil fuel turbines and nuclear turbines are the principal steam turbine types defined under this characterization.
At the present time, commercial nuclear turbines are principally used in electric power generation applications although they have been proposed for other nuclear applications such as sea water conversion plants. Nuclear turbines and their control systems generally differ according to the character of the nuclear steam generating system, i.e. the boiling water reactor system, the pressurized water reactor system, etc. Fossil fuel turbines and particularly their control systems normally also differ according to the type of steam generating system employed, i.e. the drum type boiler system, the once through boiler system, etc.
Each general type of turbine may also be subpartitioned into different subtypes on the basis of preselected turbine characteristics such as power rating, structural design, steam pressure and/or temperature design operating characteristics, number of turbine sections and stages, turbine steam flow arrangement, number of rotor shafts (i.e. presence or absence of compounding), number of reheat stages, etc. Typically, because of the region of steam table operation and other operating characteristics of reactor steam generating systems, nuclear turbines are designed to operate with dry saturated steam at a relatively low throttle pressure such as 800 psi whereas the high pressure section of a large fossil fuel electric power plant turbine would typically be designed to operate with highly superheated steam at a much higher throttle pressure such as 3500 psi.
With respect to steam turbine control, prime mover turbine controls usually operate to determine turbine rotor shaft speed, turbine load and/or turbine throttle pressure as end controlled system variables. In the case of large electric power plants where steam throttle pressure controlled by the steam generating system, turbine control is typically directed to the megawatt amount of electrical load and the frequency participation of the turbine after turbine rotor speed has been controllably brought to the synchronous value and the generator has been connected to the electric power system.
Among other types of control, propulsion turbine control typically determines the turbine shaft speed and torque as in the case of ship propulsion turbines. Extraction turbine controls are normally operated to determine turbine speed and/or load as well as extracted process steam pressure as end controlled system variables. Extraction turbine operation thus requires multivariable control system operation, i.e. the prime mover and the process steam requirements are integrated in the determination of control actions and operating strategies to be taken. Back pressure turbines and sea water conversion turbines also typically entail the use of specially functioning controls in their operation.
The end controlled plant or turbine system variable(s) and turbine operation are normally determined by controlled variation of the steam flow to one or more of the various stages of the particular type and the particular design of turbine in use. In prime mover turbine applications such as drum type boiler electric power plants where turbine throttle pressure is externally controlled by the boiler operation, the turbine inlet steam flow is an end controlled steam characteristic or an intermediately controlled system variable which controllably determines in turn the end controlled system variable(s), i.e. the turbine speed, the electrical load, or the turbine speed and the electrical load. It is noteworthy, however, that some supplemental or protective control may be placed on the end controlled variable by additional downstream steam flow control such as by control of reheat valving and to that extent inlet turbine steam flow control is not strictly wholly controllably determinative of the end controlled system variables under all operating conditions.
Among other turbine types which can operate with externally controlled throttle pressure, extraction turbines use inlet steam flow control to provide partial determination of the end controlled system variables, i.e. turbine speed and extraction pressure. Downstream steam flow control interacting with the inlet steam flow control provides the balance of the determinative control placed on the end controlled extraction turbine system variables.
Where independent external control does not wholly control turbine throttle pressure such as in boiling water reactor turbine plants or in once through boiler turbine plants, inlet turbine steam flow control may be used to regulate throttle pressure as an end controlled or constrained system variable. In that event, turbine steam flow control determines the end plant system variable(s) such as plant electrical load subject to the control or constraint of throttle pressure.
In determining turbine operation and the end controlled system variables, turbine steam flow control has generally been achieved by controlled operation of valves disposed in the steam flow path(s). To illustrate the nature of turbine valve control in general and to establish simultaneously some background for subsequent description, consideration will now be directed to the system structure and operation of a typical large electric power tandem steam turbine designed for use with a fossil fuel drum type boiler steam generating system.
Steam generated at controlled pressure may be admitted to the turbine steam chest through one or more throttle stop valves operated by the turbine control system. Governor or control valves are arranged to supply steam to steam inlets disposed about the periphery of the high pressure turbine section casing. The governor valves are also operated by the turbine control system to determine the flow of steam from the steam chest through the stationary nozzles or vanes and the rotor blading of the high pressure turbine section.
Usually, full arc admission governor valve operation with throttle valve control is employed during turbine startup primarily because excessive thermal rotor stress is caused by partial arc admission operation. At some point in the speed or load buildup dictated by efficiency and/or other considerations, the throttle valving is opened fully and steam flow control is transferred to partial arc governor valve operation.
Torque resulting from the work performed by steam expansion causes rotor shaft rotation and the reduced pressure steam is usually then directed to a reheat stage where its enthalpy is raised to a more efficient operating level. In the reheat stage, the high pressure section outlet steam is ordinarily directed to one or more reheaters associated with the primary steam generating system where heat energy is applied to the steam. In large electric power nuclear turbine plants, turbine reheat stages are usually not used and instead combined moisture separator-reheaters are employed between the tandem nuclear turbine sections.
Reheated steam crosses over to the next or intermediate pressure section of the large fossil fuel turbine where additional rotor torque is developed as the intermediate pressure steam expands and drives the intermediate pressure turbine blading. One or more interceptor and/or reheat stop valves are usually installed in the reheat steam flow path or paths in order to cut off or reduce the flow of turbine contained steam as required to protect against turbine overspeed. Reheat and/or interceptor valve operation at best produces late corrective turbine response and accordingly is normally not used as a primary determinant of turbine operation.
Additional reheat may be applied to the steam after it exits from the intermediate pressure section. In any event, steam would typically be at a pressure of about 1200 psi as it enters the next or low pressure turbine section usually provided in the large fossil fuel turbines. Additional rotor torque is accordingly developed and the vitiated steam then exhausts to a condenser.
In both the intermediate pressure and the low pressure sections, no direct steam flow control is normally applied as already suggested. Instead, steam conditions at these furbine locations are normally determined by the mechanical system design subject to time delayed effects following control placed on the high pressure section steam admission conditions.
In the typical large fossil fuel turbine just described, thirty percent of the total steady state torque might be generated by the high pressure section and seventy percent might be generated by the intermediate pressure and low pressure sections. In practice, the mechanical design of the turbine system defines the number of turbine sections and their respective torque ratings as well as other structural characteristics such as the disposition of the sections on one or more shafts, the number of reheat stages, the blading and vane design, the number and form of turbine stages and the steam flow paths in the sections, etc.
A variety of valve arrangements may be used for steam control in the various turbine types and designs, and hydraulically operated valve devices have generally been used for steam control in the various valving arrangements. The use of hydraulically operated valves has been predicated largely on their relatively low cost coupled with their ability to meet stroke operating power and positioning speed and accuracy requirements.
Previous automatic turbine control schemes involving hydraulic turbine valves were based on principally hydraulic feedback control having some mechanical couplings as shown for example in prior art extraction turbine control U.S. Pat. Nos. Bryant 2,552,401 and Marsland 1,777,470 or principally mechanical feedback control as exemplified in prior art U.S. Pat. No. Eggenberger 3,027,137. Thereafter, advances in electronic solid state circuitry with its inherent reliability made it desirable to employ electrical feedback principles for automatic hydraulic valve control in commercial applications. Electrohydraulic analog type turbine control systems are described in prior art U.S. Pat. Nos. including for example Bryant 2,262,560, Herwald 2,512,154, Eggenberger 3,097,488; 3,097,489; 3,098,176 and Callan 3,097,490.
An early solid state electrohydraulic analog-digital turbine control system known as DACA has been applied in a number of customer installations by Westinghouse Electric Corporation. The DACA system relates primarily to turbine speed control in various applications such as paper mills and ships. Extraction type analog turbine control systems also have employed electrohydraulic control as set forth for example in prior art U.S. Pat. Nos. including Wagner 2,977,768, 3,064,435, 3,091,933, 3,233,412 and 3,233,413.
Generally, prior art analog or analog-digital electrohydraulic turbine control systems employed closed loop feedback operation. Basically, the end system variable controlled by valve operation or a representation of that variable may be sensed and compared to a setpoint value to generate an error signal. Circuitry including an analog controller acts on the error signal with preset loop gain and often with a preset transfer characterization to develop a control signal which effects hydraulic operation of the turbine steam valving through a valve positioning control including a servo valve, an actuator, and a position error feedback driven controller which operates the servo valve. When the error is reduced to zero, corrective valve control action is terminated.
In prime mover turbines, a speed error signal may determine the control action alone or in conjunction with a load control signal. As another prior art turbine control loop example, multivariable extraction turbine control action requires separate speed and extraction pressure control loops with the speed and pressure error signals directly determining the speed and pressure loop control actions respectively and with crossover coupling between the loops modifying the pressure and speed loop control actions respectively.
When the end variable controlled by valve operation is turbine load as in large constant throttle pressure electric power plant turbines, the load control loop may be open or closed and it usually operates jointly with the closed speed feedback loop. After the turbine is brought to synchronous speed by speed loop operation, the speed error normally holds at zero and the load control loop operates the steam valving to determine the turbine steam flow and the amount of the total system load shared by the turbine. To hold synchronous speed, frequency participative speed control action is applied during transient speed disturbances caused by large load changes.
In some prior art cases, the load control loop may be open or substantially open in operation in that valve positions are instituted manually or automatically to provide desired or reference load, and subsequently valve setting changes are manually initiated if the generated megawatt reading or other load detecting variable is in error. Faster but still delayed load control is achieved in other art cases with the use of an interstage reheat pressure signal as a closed load loop feedback signal. The fastest load control has been obtainable with the use of impulse chamber or first expansion stage closed loop pressure feedback.
In this as well as the general prior art case, suitable characterizing circuitry may be included in the load control loop in operating upon the load demand, i.e. the load reference or the load error signal. Typically, the characterization may statically compensate for the usual nonlinear valve position-flow characteristics thereby producing a linear relationship between controlled steam flow changes and changes in the load demand level or it may introduce nonlinearity intended to produce valve back seating.
A commercially supplied prior art electrohydraulic turbine control scheme is shown and described more specifically in a printed paper entitled "Electrohydraulic Control For Improved Availability and Operation of Large Steam Turbines" and presented by M. Birnbaum and E. G. Noyes to the ASME-IEEE National Power Conference at Albany, N.Y. during Sept. 19-23, 1965. In that scheme, feedback control is employed to regulate turbine speed and load in large electric utility steam turbines. Some digital circuitry is included especially a solid state digital reference system which eliminated earlier speed/load changer motor systems for establishing the turbine speed and load setpoint changes on a permissive ramp scheduled basis. An article entitled "Automatic Electronic Control Of Steam Turbines According To A Fixed Programme" in the March 1964 issue of the Brown Boveri Review relates to similar subject matter.
Although the known various types of prior art electrohydraulic turbine control and electric power plant systems have in general provided satisfactory turbine and power plant operation and control results, they have had particular shortcomings many of which are inherent consequences of the basic character of these systems. For instance, as already indicated, it has been the practice to utilize feedback operated loops or uncorrected open loops in which transfer function circuitry provides compensation for nonlinearity in the position-steam flow characteristic curves of the turbine valves and there are inherent in this feature certain disadvantages.
The purpose of using the static compensation characterizing circuitry is to attempt to make the steam flow rather than the steam valve position proportional to the feedback error demand or the reference demand and thereby make the amount of control action proportional to the amount of demand placed on the control. It is inconvenient and often difficult to realize accurately linearizing transfer function circuitry for the variously characterized valves with which a control would be associated in any particular turbine unit or from turbine unit tc turbine unit of production. One reason for this is that each valve or valve arrangement might require a special accurately linearizing transfer function and accordingly necessitate special and relatively costly electronic hardware to obtain that function.
Another and perhaps more significant reason is that a truly linearizing transfer function circuit may not be economically and feasibly obtainable such as where the valve position-flow characteristic in general has a positive slope but along one or more curved segments it has negative sloping with zero slope turning points at each of the segment ends. Further, even where appropriate linearizing transfer function circuitry is developed for a particular valve arrangement, system usage can change the valve position-flow characteristic as a result of valve wear, etc. and the original inflexible static transfer function circuit no longer accurately achieves its purpose thereby inconveniently making maintenance modification desirable or necessary.
In the general case, it is noteworthy by extension that the same or similar comments apply regarding applications difficulties where static control system transfer functions selected before or during turbine operation are used to produce some relationship either linear or other than linear between the controlled steam condition such as flow and the demand made on the control system. Because of the related shortcomings in control loop static characterization, prior art turbine operation and control have been deficient across the turbine art from the standpoint of efficiency and accuracy. In the area of electric power plant turbines supplied by fossil fuel fired drum type boilers or other steam generating systems, inefficiencies and inaccuracies stemming from these shortcomings have caused reduced power generating control flexibility and higher generating costs.
Apart from static characterizing, another difficulty with prior electrohydraulic turbine valve control systems and associated turbine operation has been the limited utility experienced with respect to turbine dynamics, i.e. controlling the speed of steam valve response and the speed of turbine energization response. Typically, turbine control systems have control looping which is dynamically characterized with proportional action and with appropriate gain for stable valve positioning and stable turbine drive responses. A loop so characterized may or may not result in desired dynamic steam valve response and desired dynamic turbine steam energization response and, in electric power plants, desired power generation response as the system operating conditions undergo variation.
One aspect of the dynamic characterization difficulty stems from the fact that different magnitudes of change in the valve position setpoint may require different positioning loop gains in order to achieve the desired dynamic valve positioning response on a consistent basis. For example, it may be desired to produce fast stable valve positioning operation with huntless 10% overshoot. A small position setpoint change may require a first gain G.sub.1 to achieve this response while a larger position setpoint change may require a second and higher gain G.sub.2. Since the positioning gain is typically fixed, the desired valve positioning response can only be achieved within a limited range of valve position setpoint changes.
Further difficulty has been experienced with conventional turbine control dynamic characterization from the standpoint of control loop bandwidth limitations on the amount of loop gain usable for achieving stable response. This limiting and inefficient quality of the prior art requires relatively reduced loop gain to limit noise interferences with control action. Thus, a limit is placed on the speed with which valve position and turbine steam energization responses can be achieved where a faster response might otherwise be desirable and obtainable within the limits of turbine thermal and mechanical dynamics. Bandwidth limitations on turbine process control capability especially arise in turbine control systems having cascaded loops with summing junctions, such as in large electric power plant turbine control systems where the gain of an inner valve positioning loop acts on the output of an outer load control loop and thereby requires a cutback in outer loop gain to achieve adequately low response level to outer load control loop noise signals.
Another aspect of the dynamic characterization difficulty stems from the fact that a typical proportional action loop, even though it may act in some circumstances with the desired fast and accurate valve positioning within the limits of turbine thermal and mechanical capabilities, will in most cases cause overdamped turbine steam energization response because a changed steam flow requires time to cause the steady state steam drive energization of the turbine to reach the new level corresponding to the new steam flow. The significance of this shortcoming varies in accordance with the amount and the significance of the excessive time delay involved in the turbine energization response. In the case of large electric power turbines, the difference in time between critical and typically overdamped responses is relatively short in comparison with other plant operating limitations and therefore has not been too objectionable. In other words, electric power plant turbine energization response normally is nonoptimal in the strictest sense, yet little or no power plant operating advantage is normally obtained by increasing the speed of turbine energization response because of other plant constraints. However, in at least some possible electric power plant applications and in other turbine applications across the turbine art where optimal or more nearly optimal turbine dynamics have been desirable or would be desirable if practically achievable, previous turbine controls have been somewhat deficient.
To produce some increase in turbine response speed, prior controls might use some dynamic characterization including analog rate action for example. In that event, steam valve positioning may be produced within the limits of turbine thermal and mechanical dynamics with valve position overdrive which persists beyond the previously noted quickly executed 10% overshoot used for achieving fast nonhunting valve positioning. As a result, steam flow temporarily overshoots, and faster nonovershoot turbine drive energization is produced as valve position is ultimately countercorrected to provide the required steady state steam flow. However, as in the case of static characterization, the dynamic characterization cannot be adjusted conveniently to provide stable and consistently faster turbine response under varying operating conditions.
Prior art difficulty in the area of dynamic characterization and its role in determining steam valve response and turbine energization response and, in electric power plants, power generation response thus stems from inability to achieve particular responses as well as from relatively rigid inability to achieve (1) conveniently selectable response after system installation and before system operation and (2) convenient or automatic variation in steam valve response and turbine energization response needed after system startup to meet particular performance specifications under different operating conditions or to satisfy the requirements of optimizing or near optimizing control. Operating and control efficiency and accuracy have thus been adversely affected in the area of electric power plant turbines as well as across the entire turbine art by inflexibility of control loop dynamic characterization.
As in the case of static characterization and other prior art deficiencies, slowness of turbine control and inaccuracy and inefficiency of turbine operation resulting from inadequate prior art dynamic characterization have led to objectionable deviation of the end controlled system variable(s) from the desired value(s). For example, steam turbine slowness in driving an electric power plant generator accurately to a new power contribution level can negate some of the economic gain otherwise achieved by the functioning of an economic dispatch computer.
In addition to relatively costly hardware changes required for changed static characterizing transfer functions from unit to unit of a particular type of turbine, there have been long standing, costly and inflexible differences in hardware design among the conventional control systems tailored for the various types of turbines, i.e. extraction turbines, large electric plant turbines, boiling water reactor turbines, pressurized water reactor turbines, etc. Although different specific turbine operating characteristics and control results are necessary for the various turbine types, the capital costs associated with the wide variety of prior art turbine control hardware needed for this purpose have, certainly along with other factors, generally inhibited the marketability of steam turbines and steam turbine controls.
The relatively high capital cost characteristic of conventional inflexible turbine controls has also in general limited the extent to which functional sophistication can be incorporated in turbine operation, i.e. more advanced functioning requires increasingly more costly hardware application. Inflexibility and high cost of conventional turbine controls has more specifically restrictively affected development of integrating controls for large system applications which include steam turbines as a large component piece of equipment. Thus, the special engineering needed for interfacing prior art turbine controls with plant associated controls, such as steam generating system controls in an electric utility plant, has for economic and other reasons limited the advanceability of the turbine operation and control art by limiting the extent to which the interfacing can be made more integrational or more interdependent.
In a similar manner, inflexibility of conventional large turbine control schemes has even caused the capital cost of state of the art hardware systems to become objectionable. Thus, interlock and supervisory circuitry and equipment required for system monitoring, supervision, protection and sequencing has in many cases expanded to comprise as much as eighty percent of the control system hardware cost. The inconvenience and cost of modifying the wired hardware after installation to achieve needed changes in interlock, supervisory and like functions has resulted in further difficulty and objection.
In brief summary, it is clear that prior art operation and control of the various types of steam turbines including large electric power steam turbines are characterized with (1) inaccuracy and inefficiency in steam turbine operation and electric power plant operation due to limited steam valve operating accuracy and limited and inflexible control loop static characterization, (2) inaccuracy, inefficiency and slowness in steam turbine and electric power plant operation due to limited steam valve control flexibility and limited control loop dynamic characterization, (3) inaccuracy and inefficiency in the operation of electric power and other cascade loop controlled steam turbines and in electric power plant operation due to bandwidth limited control system response speed, (4) limited steam turbine and turbine control marketability caused by relatively high cost electrical control systems in turn caused generally by special hardware requirements such as extensive interlocking and supervisory hardware differences from system to system, and (5) limited steam turbine and turbine control marketability caused by the relatively high hardware cost associated with advancement of the art.
The state of the turbine operation and control art is improved and advanced by the present invention since it is arranged and organized to provide improved turbine performance with reduced relative cost. It achieves these results in its preferred form with the employment of a programmed digital computer.